Oil extraction and production systems can vary as a function of the geological formation of the reservoir and the characteristics of the fluids thereof. Having determined the location of a reservoir, wells are created using drills or drilling rigs.
A well passes through several rock formations and a steel pipe, known as the “casing”, is normally inserted and cemented into it. At least one pipe of lesser diameter, known as the “tubing”, is placed inside the casing, through which flow the fluids from the reservoir(s).
If the pressure accumulated in the reservoir is sufficiently high, the oil is naturally expelled from the reservoir through the wells, this technique only requiring the installation of a pipe that communicates this reservoir with the external means. These wells are known as “flowing wells”.
The pressure in the reservoir may also be very low, resulting in production with a less-than-desired or even zero flow rate. In this case, the well requires external intervention to extract the oil from the reservoir. These wells are known as “artificial lift production” wells. This intervention involves means such as mechanical extraction using pumps inside the well or gas lifting, which is the injection of gas at the bottom of the well, supplementing the gas naturally occurring in the fluid flow of the reservoir.
In a conventional arrangement for the latter method, high-pressure natural gas is injected into a space in the well, known as the annulus, which is formed between the casing of this well and the tubing.
At certain points along the tubing are installed valves known as “gas-lift valves”, which are primarily intended to enable the controlled flow of gas injected into the annulus to the inside of this tubing.
The valves are installed in piping accessories known as mandrels. There are essentially two types of mandrel: conventional and side-pocket mandrels. Conventional mandrels require the tubing to be removed to replace valves after the well has been fitted. Conversely, with side-pocket mandrels, valves can be removed using a steel-wire operation known as “wireline”, without the need to remove the tubing. Consequently, side-pocket mandrels constitute a significant advantage and are therefore the most commonly used. There are some minor structural differences between valves designed for one type of mandrel or the other, but the internal elements are essentially the same and a person skilled in the art would only require a description of a valve for one type of mandrel to determine the adaptations required for use with the other type of mandrel.
In fact, not all of these valves are used in normal operating circumstances. Some of them are only opened during unloading of the well following a rig intervention, or if it is necessary to restart production as a result of a production stoppage of the well, be it accidental or planned.
Normally, the injection of gas from the annulus to the inside of the tubing is effected by just one gas-lift valve, usually the one that is at the deepest point of the well, known as the operating valve.
Although arrangements with several unloading valves and an operating valve are very common, there are practical situations where just one gas-lift valve is placed in the well, this valve then acting both as operating valve and unloading valve, when required.
When it comes into contact with the fluids inside the tubing, the injected gas expands, causing a reduction in the apparent density of the multi-phase mixture and enabling the fluids coming from the reservoir to flow at a given rate.
In addition to gas-lift valves inside the well, it is also common to install some sort of control valve outside the well to regulate the injection pressure of the gas into the annulus. This valve is often simply a gas injection choke.
The gas may be injected continuously and without interruption, which is known as continuous gas lifting. Alternatively, it may be injected intermittently, according to injection and idle cycles, which is known as intermittent gas lifting. The latter method is generally used in wells draining low-productivity reservoirs, while the continuous method is used in high-productivity wells. The gas-lift valves in both injection methods (continuous or intermittent) are identical or very similar.
In conventional arrangements of wells with continuous gas-lift systems, the most conventional models of operating valves use an element, fitted into a recess inside the body of said valve, to regulate the rate of gas injection in the form of a small cylindrical disc or plate the centre of which has a circular orifice of a specific diameter. This disc is also known as an “orifice plate” or valve “seat”. The orifice has sharp or slightly chamfered edges.
Conventional unloading valve models, in addition to the aforementioned regulating element (orifice plate), have an opening and closing mechanism, generally a bellows charged with nitrogen that, as a function of the pressures in the annulus and the tubing, controls a rod having a spherical or conical tip that seals the orifice of the seat, preventing the gas injection, or remains in a withdrawn position in which injection is possible at a given flow rate.
Gas-lift valves are also provided with at least one check valve, located downstream of the orifice, such as to prevent any unwanted leaking of the oil from inside the tubing towards the annulus when the pressure differential is conducive to this reverse flow, which may occur during a production stoppage.
The shape of the orifice plate naturally leads to the appearance of vortices. Thus, the gas flow attains a high degree of irreversibility and causes a significant pressure drop.
An additional challenge to be overcome is the generation of major difficulties related both to the calculation of gas flows through the perforated disc and to the modelling and analysis of the results of the design itself.
Developments in research into a solution for the aforementioned issues have led the applicant to design a gas-lift valve that uses a venturi instead of the perforated disc with sharp edges.
Indeed, it has been observed that the irreversibilities of the gas flow are greatly reduced and the diffuser caused a significant recovery of pressure. As a result, the critical gas flow is reached with a lower pressure differential through the valve than that required in a traditional orifice valve and, therefore, the gas flow is easier to keep constant.
However, in a gas-lift valve that uses a venturi, hereinafter referred to simply as a venturi valve, the so-called subcritical region of the performance curve is very narrow and, therefore, it is not possible to operate in this region, because the variations in gas flow injection rate as a function of the pressure variations in the tube are huge and the instabilities induced in the flow constitute a major hazard to operation.
The venturi valve can therefore be used in practice as a device for injecting a constant gas flow, i.e. to operate in the critical region. In orifice valves, the pressure differential required for critical flow is very high for practical standards and operation occurs in the sub-critical region.
Although the venturi valve solves significant problems in this lifting technique, it adds a major problem relating to the operational flexibility of the installation, because it is not possible to achieve relatively large variations in the gas flow rate by varying the pressure in the casing, which is how well characteristics are adjusted to optimise flow rate from an economic perspective when using continuous gas lifting.
In practice, on account of this reduced flexibility, designers prefer to use old orifice valves in situations that will require relatively large variations in gas injection flow rates throughout the production life of the well and they want to avoid having to undertake costly valve-replacement work.
It would be beneficial for the art to develop a valve for use in gas lifting operations that combined high performance with application flexibility in different design situations.